The production of oil and gas reserves has taken the industry to increasingly remote inland and offshore locations where hydrocarbon production in extremely cold climates is often required. When oilwells are completed in extremely cold environments, problems occur when a submersible pump is first installed and thereafter any time production is stopped. As a result, production techniques in remote and extreme climates require creative solutions to problems not usually encountered in traditionally warmer areas.
One problem often encountered in cold climate hydrocarbon production has been finding ways to maintain adequate hydrocarbon flow characteristics in production tubing. For example, under arctic conditions, a deep permafrost layer surrounds the upper section of a wellbore. The cold permafrost layer cools the hydrocarbon production fluid as it moves up the production tubing, causing hydrates to crystallize out of solution and attach themselves to the inside of the tubing. Paraffin and asphaltene can also deposit on the inside of the tubing in like manner. As a result, the effective cross-section of the tubing is reduced in many portions of the upper section of the wellbore, thereby restricting and/or choking off production flow from the well. Also, if water is present in the production stream and production is stopped for any reason such as a power failure, the water can freeze in place and block off the production tubing.
Wellbores having electrical submersible pumps experience higher production pressures due to the above restrictions. The higher production pressures accelerate wear of the pump and reduce the run life of the system, causing production costs to increase. Wells without downhole production equipment also suffer from similar difficulties as production rates fall due to deposition buildup. One method of overcoming these problems is to place a heating device of some sort adjacent to the production tubing to mitigate fluid temperature loss through the cold section of the well.
Presently, conventional heating of the production tubing utilizes a specialized electrical heat trace cable incorporating a conductive polymer which is attached to the tubing. This polymer heat trace cable is designed to be temperature sensitive with respect to resistance. The temperature sensitive polymer encapsulates two electrical conductors. As the electrical current flows through the polymer between the conductors it causes resistance heating within the polymer, which in turn raises the temperature of the polymer. As the temperature increases, the resistance of the polymer increases and the system becomes self regulating. However, this conventional approach to making a power cable for application in oil wells has several severe limitations.
One primary disadvantage of heat trace cable with conductive polymers is that these polymers can easily be degraded in the hostile environment of an oil well. To overcome this, several layers of expensive high temperature protective layers have to be extruded over the heat trace cable core. This increases the cost substantially and makes the cables very difficult to splice and repair. Another disadvantage of heat trace cables of conventional conductive polymer design is that the length of the cables is limited due to the decrease in voltage on the conductors along the length. This requires extra conductors to be run along the heat trace cable to power additional sections of heat trace cable deeper in the well. These extra conductors also require extra protection with appropriate coverings, and they require extra splices along the cable assembly. Splices also reduce reliability of the system and the coverings add further increase to the cost.
Conventional electrical submersible pumps use a three-phase power cable that has electrical insulated conductors embedded within an elastomeric jacket and wrapped in an outer armor. The insulation is fairly thick, being typically in the range from 0.070 to 0.090 inches in thickness. One type, for hydrogen sulfide protection, employs extruded lead sheaths around the insulated conductors. An elastomeric braid, tape or jacket separates the lead sheaths from the outer armor. Other types of cable use non-metal sheaths.
One solution is set forth in U.S. Pat. No. 5,782,301 to Neuroth, et al. for an "Oil Well Heater Cable". The 5,782,301 patent teaches a heater cable to be strapped alongside tubing in a well to heat production fluids flowing through the tubing. The heater cable has three copper conductors surrounded by a thin electrical insulation layer. An extrusion of lead forms a protective layer over the insulation layers. The lead sheaths have flat sides which abut each other to increase heat transfer. A metal armor is wrapped around the lead sheaths of the three conductors in metal-to-metal contact. Three phase power is supplied to the conductors, causing heat to be generated which transmits through the lead sheaths and armor to the tubing.